Hydrocarbons, such as oil and gas, are recovered from underground formations through drilled wells. The success of any well drilling operation depends on many factors and one of the most important is the drilling fluid. Drilling fluids, also called drilling muds, are circulated from the surface through the drill string and introduced to the bottom of the borehole as fluid spray out of drill bit nozzles and subsequently circulated back to the surface via the annulus between the drill string and the well hole. Drilling fluids are formulated to cool down and lubricate the drill bit, remove cuttings from the hole, prevent formation damage, suspend cuttings and weighting materials when circulation is stopped, and cake off the permeable formation by retarding the passage of fluid into the formation.
Drilling operations face great technical challenges with drilling fluid loss being the most notable. Fluid loss is also an issue for other well fluids such as kill fluids, completion fluids and stimulation fluids. Drilling fluid loss is the partial or complete loss of fluid to the formation during drilling. Loss of fluid causes several severe consequences to the drilling operations. Loss of fluid, in turn, impacts the cost of drilling. Therefore, drilling and other well fluids are typically formulated with loss circulation materials or additives (LCM). The primary function of LCM is to plug the zone of loss in the formation, away from the borehole face so that subsequent operation will not suffer additional fluid losses. LCM forms a barrier which limits the amount of drilling fluid penetrating the formation and prevents loss.
Lost circulation is the leading cause of non-productive time on an oil rig1 or drilling site. This is a particular problem while drilling with a narrow mud weight window, for example in depleted reservoirs. Mud weight required for well control and to maintain a stable wellbore generally exceeds the fracture resistance of a formation. Casing strings are designed at different stages of the well so that the well can be drilled where the mud weight window is balanced between the pore and fracture pressure with depth. This boundary value also typically includes a safety of trip tolerance added to the pore pressure and subtracted from the fracture pressure.
A drilling fluid that effectively increases the fracture pressure tolerance gradient strengthens the wellbore and increases the fracture gradient. The result of this effect is that the drilling design of a well might require one or more less drill string casings/hole sizes which highly affects the drilling and completion economics of a well. As an example, a three different hole size casing program with surface, intermediate and main hole casing can, with these new fluids, be designed with only one surface and one main borehole casing which could then have a larger hole size in the production zone and produce at higher rates as well. This is also called a mono-bore oil and gas wellbore. The more casing sizes run on a well, the higher the potential is to reduce the number of strings and save money.
In a depleted reservoir, there is a drop in pore pressure as the reserves decline which weakens the hydrocarbon-bearing rocks but neighboring low permeability rocks such as shale may maintain their pore pressure. The result is that the mud weight required to support the shale exceeds the fracture resistance of the sands and silts. This leads to severe mud losses that prevent drilling ahead and creates the possibility of sticking the bottom hole assembly, drill pipe or liner/casing.
There are different technologies for dealing with this problem but preventive wellbore strengthening technologies are preferred. Wellbore strengthening increases the resistance of formations to circulation loss during drilling operations. By strengthening the wellbore, the width of the operating mud window is increased or the gap between the pore pressure and fracture gradient in the formation is widened. Wellbore strengthening may also prevent loss circulation, wellbore instability, stuck pipe, differential sticking, kick and blow out, excessive number of casings run and cutting removal issues.
One focus for strengthening wellbores is the properties of the solid contents of the drilling fluids since they play a key role in the process. LCM has been added to drilling fluids to successfully strengthen wellbores. This was achieved by widening fractures and effectively plugging them with the right sized particle LCM. This isolates the fracture tip from the fluid pressure which then controls the fracture propagation and ultimately increases the hoop stress around the wellbore.2-8 The result is that the fracture pressure is increased. This allows an operator to use a drilling mud with a higher mud weight through the strengthened wellbore to access other sections of the formation.
It was previously thought that LCM's would only plug fractures and strengthen wellbores in permeable formations. LCM's were not effective in impermeable formations. Also small particles that only plugged the pore throat would not effectively plug a fracture and seal the formation. Leak off of the base fluid was required.6 Nanoparticles were very effective at plugging pore throats but were not thought to be effective in strengthening wellbores. Nanoparticles have very different properties as compared to its parent material.10 
Nanoparticles have been used in well fluids for a number of purposes.
U.S. Pat. No. 3,622,513 (1971) is directed to oil-based drilling fluids with improved plastering properties and reduced fluid loss properties at extreme conditions of borehole temperature and pressure. The drilling fluids contain asphaltous material and a weighting agent, usually barium sulfate having a particle size of 100 to 200 μm, which primarily result in the formation of the filter cake to prevent fluid loss to the formation. The drilling fluids also contain a small amount of a secondary weighting material inert to the fluid and having a particle size of less than 3 μm. The fluids showed some reduction in fluid loss. However, the compositions required extra additives, such as the asphalt material, which bind to the nanoparticles and acted as a filler or plaster between the particles at high temperature to reduce the fluid loss. The fluid may also contain other lost circulation additives.
U.S. Pat. No. 6,579,832 (2003) is directed to a method of rapidly adjusting the fluid density of drilling fluids using superparamagnetic nanoparticles. The particles were effective to change the density state of the fluid required to control subsurface pressures, and to preserve and protect the drilled hole until a casing is run and cemented. The nanoparticles were sized between 0.5 and 200 nm and formed into clusters having an average size of between 0.1 and 500 μm. The clusters were formed by incorporating the nanoparticles into a matrix of glass or ceramic. Group VIII metals Cd, Au and their alloys were found to provide an excellent result in adjusting fluid density in a reversible manner. 90% of the supermagnetic nanoparticles from the treated drilling fluid from the downhole location were recovered by a magnetic field at the surface resulting in the adjustment of drilling fluid density within a short period of time and circulation of the magnetic nanoparticles to the surface level for reuse in the drilling fluid.
U.S. Patent Application 2009/314549 (2009) considered compounds for reducing the permeability of shale formations using specific nanoparticles in the drilling fluids. By identifying the pore throat radii of shale samples, fine particles were selected that would fit into the pore throats during the drilling process and create a non-permeable shale surface. The drilling mud was a water-based mud with nanoparticles having a size range of 1-500 nm selected from silica, iron, aluminum, titanium or other metal oxides and hydroxides and also composed of a surface active agent. The aqueous well-drilling fluid contained between about 5 to 50 weight percent, based on the weight of the aqueous phase and resulted in a reduction in permeability of the shale, which resulted in drastic reduction of absorbed water and potential for collapse. The minimum concentration required to reduce the fluid penetration was 10 wt % nanoparticles and in some cases, required high concentrations of nanoparticles of 41 wt %.
Aqueous-based drilling fluids generally require a higher concentration of nanoparticles than other types of drilling fluids. They also require additional additives such as surfactants to stabilize the nanoparticles in the fluid system whereas other based fluids, such as invert emulsion drilling fluids, do not need to include other additives to completely disperse the nanoparticles. Nanoparticles that have a hydroxyl group tend to agglomerate faster in aqueous based fluids. This agglomeration causes poor dispersions and the addition of surfactants reduces this problem. Poor dispersion in turn causes fluid loss even after the addition of the nanoparticles. As well, flocculated or poorly dispersed suspensions form more voluminous sediments. The resulting filter cake is not as dense and impenetrable as compared to that formed from a stable suspension. Therefore, the use of nanoparticles in aqueous based fluids teaches little about its use in non-aqueous-based fluids such as invert emulsions.
A related publication is “Use of Nanoparticles for Maintaining Shale Stability” Sensoy (2009). It also discloses the use of nanoparticles in an aqueous drilling fluid for nanopore throat reduction. It found that the 5 wt % of nanoparticles in the fluid was less effective and the minimum level of nanoparticles was at least 10 wt %. It also tested higher levels of 29 wt % and 41 wt %. The paper concludes that higher amounts of nanoparticles were preferable to achieve the nanopore throat reduction.
U.S. Patent Application 2011/59871 (2010) relates to a drilling fluid including graphene and chemically converted nanoplatelet graphenes with functional groups. The graphene comprised about 0.001% to about 10 vol % of the drilling fluid. The functionalized chemically-converted graphene sheets were about 1.8 to about 2.2 nm in thickness. Whatman 50 allowed some graphene oxide to pass through the filter. Nanoparticles pass through the filter paper along with the filtrate which may block the interporosity of rock and create formation damage. This may result in permeability impairment and thus lead to a reduction in oil and gas production.
U.S. Patent Application 2009/82230 (2009) relates to an aqueous-based well treatment fluid, including drilling fluids, containing a viscosifying additive. The additive has calcium carbonate nanoparticles with a median particle size of less than or equal to 1 μm. The amount of calcium carbonate nanoparticles used in the drilling fluid was approximately 20 wt %. The nanoparticles used in the well treatment fluid were capable of being suspended in the fluid without the aid of a polymeric viscosifying agent. The addition of the nanoparticles altered the viscosity of the fluid. Nanoparticles suspended in a well treatment fluid even at high temperature as 350° F. typically exhibit sag (inadequate suspension properties) particularly at high temperatures of around 350° F. The viscosity changes of a fluid upon addition of nanoparticles were well reported.
U.S. Patent 2011/162845 discloses a method of servicing a wellbore. It introduces a lost circulation composition into a lost circulation zone to reduce the loss of fluid into the formation. The lost circulation composition comprised Portland cement in an amount of about 10 wt % to about 20 wt % (of the lost circulation composition), nanoparticles and in particular nano-silica in an amount of about 0.5 wt % to about 4 wt % and having a particle size of about 1 to about 100 nm, amorphous silica in an amount of about 5 wt % to about 10 wt %, synthetic clay in an amount of about 0.5 wt % to about 2 wt %, sub-micron sized calcium carbonate in an amount of about 15 wt % to about 50 wt % and water in an amount of about 60 wt % to about 75 wt %. Loss circulation additives are formed with a mix of nanocomponents and cement to reduce the setting time for mud cake formation and development of gel strength. However, high amounts of the nanoparticles are required with the cement to develop the mud cake formation and gel strength.
By virtue of their very small sizes, nanoparticles (NPs) have the potential of acting as effective lubricant additives. Their size and shape enable them to enter contact zones between surfaces easily. Inorganic nanoparticles mostly do not display any affinity to oil and may not be affected by the mud type. In-situ and ex-situ techniques for forming a wide variety of well dispersed NPs in an invert emulsion as well as water-based drilling fluid have been detailed in the art (Husein et al., 2012). These methods rely heavily on high shearing, which produces finely dispersed water pools, in the case of invert emulsion drilling fluids, and the use of these water pools as nanoreactors to form NPs with sizes mainly below 100 nm. Once formed, these NPs display very high stability in the mother drilling fluid and interact very effectively with the rest of the drilling fluid (Husein et al., 2012). Previous experiments showed that these particles perfectly seal filter cakes by creating crack-free, very smooth surfaces (Husein et al., 2012). Therefore, these particles contribute to the formation of slippery layers between the borehole and the drill string leading to lower overall friction coefficient and, subsequently, increase the extended reach of horizontal drilling. Moreover, due to the small sizes of these particles, the wear and tear of down hole equipment and tools becomes negligible as less kinetic energy (nano sized particles achieve lower sedimentation speed compare to the large sized particles) and abrasive action is encountered. Overall, the application of nanoparticles in drilling fluid presents a good potential for reducing friction while drilling and, hence, improve the extended reach.
Other references, such as Amanullah et al. 2011, consider the use of small amounts of nanoparticles in water and indicate the potential for beneficial effects on differential sticking, torque reduction and reduction of drag problems in certain types of drilling. However, these references experiment with nanoparticles in water and require very active stabilizers to maintain the nanoparticle dispersions or look at the interaction of nanoparticles with other components that may be present in a well fluid. The references do not provide data directly relevant to results in industrial drilling fluids but merely indicate further areas for research.
There is therefore a need for an additive for drilling fluids to more effectively strengthen the wellbore during drilling. This is achieved by plugging fractures with nanoparticles and granular particles present in the fluid in low amounts.